Ethylene glycol elimination in amine loop for more efficient gas conditioning

This paper aims to address the points where MEG has negative effect on gas sweetening process and what the practical ways to reduce its effects are.

RESEARCH ARTICLE

Ethylene glycol elimination in amine loop

for more efficient gas conditioning

Nasibeh Hajilary1* and Mashallah Rezakazemi2

Abstract

The gas sweetening unit of phase 2 and 3 in South Pars Gas Field (Asalouyeh, Iran) was first simulated to investigate the effect of mono ethylene glycol (MEG) in the amine loop MEG is commonly injected into the system to avoid

hydrate formation while a few amounts of MEG is usually transferred to amine gas sweetening plant This paper aims

to address the points where MEG has negative effects on gas sweetening process and what the practical ways to reduce its effect are The results showed that in the presence of 25% of MEG in amine loop, H2S absorption from the sour gas was increased from 1.09 to 3.78 ppm Also, the reboiler temperature of the regenerator (from 129 to 135 °C), amine degradation and required steam and consequently corrosion (1.10 to 17.20 mpy) were increased The energy consumption and the amount of amine make-up increase with increasing MEG loading in amine loop In addition, due to increasing benzene, toluene, ethylbenzene and xylene (BTEX) and heavy hydrocarbon solubility in amine

solution, foaming problems were observed Furthermore, side effects of MEG presence in sulfur recovery unit (SRU) such as more transferring BTEX to SRU and catalyst deactivation were also investigated The use of total and/or partial fresh MDEA, install insulation and coating on the area with the high potential of corrosion, optimization of

opera-tional parameters and reduction of MEG from the source were carried out to solve the problem The simulated results were in good agreement with industrial findings From the simulation, it was found that the problem issued by MEG has less effect when MEG concentration in lean amine loop was kept less than 15% (as such observed in the indus-trial plant) Furthermore, the allowable limit, source and effects of each contaminant in amine gas sweetening were illustrated

Keywords: CO2 and H2S absorptions, Mono ethylene glycol, Amine gas sweetening, Corrosion, Foaming

© The Author(s) 2018 This article is distributed under the terms of the Creative Commons Attribution 4.0 International License ( http://creat iveco mmons org/licen ses/by/4.0/ ), which permits unrestricted use, distribution, and reproduction in any medium, provided you give appropriate credit to the original author(s) and the source, provide a link to the Creative Commons license, and indicate if changes were made The Creative Commons Public Domain Dedication waiver ( http://creat iveco mmons org/ publi cdoma in/zero/1.0/ ) applies to the data made available in this article, unless otherwise stated.

Introduction

Natural gas is produced from wells with a range of

These contaminants should be removed from the natural

gas to meet typical specifications for use as commercial

fuel or feedstock for natural gas hydrate, liquefied

natu-ral gas (LNG) plants, gas turbines, industrial and

from point of safety, environmental requirements,

corro-sion control, product specification, decreasing costs, and

prevention of catalysts poisoning in downstream facilities

Many methods have been employed to remove

hydrocarbon streams including adsorption,

amine gas treating plant is commonly faced with two major problems: corrosion and instability of

con-siderable effect on the efficiency of the gas sweetening unit In most amine based sour gas treating process, the conventional alkanol amines such as monoethan-olamine (MEA), diethanmonoethan-olamine (DEA), methyl dieth-anolamine (MDEA), disopropdieth-anolamine (DIPA), and

Open Access

*Correspondence: n.hajilari@gu.ac.ir; nasibeh.hajilary@gmail.com

1 Department of Chemical Engineering, Faculty of Engineering, Golestan

University, Gorgan, Iran

Full list of author information is available at the end of the article

diglycolamine (DGA) is used to separate H2S and CO2

industrial plants because it has some advantages over

energy consumption in regeneration section

Mono ethylene glycol (MEG) is commonly injected

into the system from two different points (wellhead and

gas receiving facilities) as corrosion and hydrate

inhibi-tor especially during winter time when the potential of

condensation corrosion and hydrate formation are high

In phases 2 and 3 through the gas path, MEG is injected

at sea line, before HIPPS valve, and after the

High-pres-sure separator drum A few amounts of MEG is usually

transferred to the amine gas sweetening plant The MEG

concentration gradually increases in amine gas

sweet-ening plant even to more than 25% A large build-up of

injection chemicals can eventually lead to fouling and

can cause changes in solution physical properties, such as

viscosity and mass transfer

South Pars is a giant gas reservoir shared with Qatar

with more than 20 phases The phases 2 and 3 of South

Pars gas refinery has been planted to treat the produced

gas through four gas treating trains and stabilize the

accompanied condensate from the gas reservoir

Nowa-days, about 2500 million standard cubic feet per day

(MMSCFD) of gas is fed to this plant In phases 2 and

3, the untreated gas is transferred via two 30″ pipelines

to onshore facilities for treatment MEG is transferred

by means of two 4″ piggy back lines to the wellhead for

hydrate prevention and low dosage hydrate inhibitor

(LDHI) is being used as a backup

The main purpose of the current study is to find where

MEG has negative effects on gas sweetening process

and what the practical ways to reduce its effect are The

effects of MEG injection on amine gas sweetening and

sulfur recovery unit (SRU) units were also studied Since

the presence of MEG was not predicted in the design

of gas sweetening unit, it seems the phases 2 and 3 was

the first gas plants to deal with this problem Other gas

refineries in South Pars Gas Field which used MEG as a

hydrate inhibitor are gradually encountering this

prob-lem Furthermore, a certain value was not found in the

literature for the maximum allowable of MEG content in

amine loop To overcome the problems issued by MEG in

amine loop, four different methods including: (1)

chang-ing operational parameters in the presence of MEG in

amine loop; (2) reducing MEG loading in amine loop

by total or partial discharging of amine; (3) enhancing

resistant to corrosion; (4) developing a strategy to track

the source of MEG in amine loop were suggested and

investigated

Gas sweetening unit description

Phases 2 and 3 of South Pars Gas Field were designed for processing of sour gas by means of four MDEA based amine units (licensed by ELF Aquitaine which does not

acid gas for Claus SRU) The composition of sour gas feed

The objective of the gas treatment unit is to meet the design sweet gas specification which must contain less

suit-able acid gas for processing in the SRU’s This certain specification of product in industrial plants is commonly achieved through an amine unit including absorption and a regeneration sections In the absorber, amine

a sweetened gas stream and a rich amine (a rich amine

Table 1 Characteristics of  sour gas feed to  the  gas sweetening unit (units 101 and  108) of  phases 2 and  3

in South Pars Gas Field (Asalouyeh, Iran)

and CO2) The rich amine after passing through a flash

drum and increasing its temperature in some

exchang-ers routed into the MDEA regenerator (a stripper with a

reboiler) to produce lean amine (a lean amine is a

solu-tion regenerated from acid gases) that is come back to the

absorber The stripped acid gas from the regenerator with

(less than 60%) is routed into a Claus SRU to produce the

liquid sulfur Sweet gas from the absorber is also routed

to the dehydration unit A schematic of phases 2 and 3

and the same but opposite take place in the regenerator

In this research, the gas sweetening and sulfur recovery

units (SRUs) (Units 101 and 108, phases 2 and 3, South

Pars Gas Field, Asalouyeh, Iran) were simulated using

ProMax (Version 2.3) and Aspen HYSYS (version 7.8),

(1)

(2)

3

and SULSIM (version 6) simulators and a schematic of

simula-tions were used to perform a parametric study to pre-dict the operational parameters change as a function of MEG content in amine loop and also to better identifying

of operational conditions Acidic gases and amines are weak electrolytes, which partially dissociate in the aque-ous phase Hence, electrolyte-NRTL model and Soave– Redlich-Kwong (SRK) equation for thermodynamically modeling of state in Aspen HYSYS were used Also,

“amine sweetening PR” property package and “TSWEET” kinetics model were selected in ProMax to provide com-plete information about ionic analysis, mass, and molar

Results and discussion

Regenerator bottom temperature

The primary or secondary amines in MDEA solution are commonly formed at higher temperatures because

Fig 1 Schematic of the gas sweetening unit (Unit 101) of phases 2 and 3 in South Pars Gas Field (Asalouyeh, Iran) designed by total company

Fig 2 Schematic of the simulated gas sweetening unit [unit 101 of phases 2 and 3 in South Pars Gas Field (Asalouyeh, Iran)] as from a ProMax, b Aspen HYSYS and c SULSIM software

MDEA would go through demethylation/dealkylation

alkyl groups with hydrogen atoms in MDEA using the

free radical mechanism Hence, the effect of the

regenera-tor bottom temperature on amine degradation was

inves-tigated Since the various MEG concentrations affect the

boiling point of the solution in the system, the variation

of boiling temperature of the aqueous solution of MDEA

at a 45 wt% concentration as a function of MEG loading

aqueous MDEA solution increases in presence of MEG

content This boiling point elevation occurs because the

boiling point of MEG is higher than that of water,

indi-cating that an MDEA/MEG solution has a higher boiling

point than a pure MDEA

The primary and secondary amines are commonly

need high steam demand for regeneration in compare

to MDEA To prevent primary or secondary amines

formation in MDEA solution, the temperature of the

reboiler shall not increase more than 132  °C

value exceeds frequently and after using fresh amine, the reboiler temperature decreases to the allowable range (less than 130  °C) Inducing high temperature degrades amine, produces some acids causing corro-sion Indeed, amine reacts with acids and forms heat stable salts (HSS) This issue may carry out when the stability of salt reduced in the places where some dis-associations occur in a site-specific location in the gas sweetening unit Corrosion takes place when that disas-sociations form a corrosion cell with metal in the unit Some issues are also appeared by the chelating effect of the formed acids The chelating effect is the increased affinity of chelating ligands toward a metal ion in com-parison to the affinity of similar non-chelating ligands toward the same ion However, the chelating effect may

Table 2 The comparison of the simulation results of the gas sweetening unit with Promax with actual data

Amine inlet to the regenerator reboiler CO2 loading (mol%) 0.018 0.017

H2S loading mole/mole amine 0.0038 0.0046

CO2 loading mole/mole amine 0.0016 0.0018

Table 3 Chemical properties of MEG

Ideal liquid density (kg/m 3 ) 1110.71

120 130 140 150 160 170 180 190

MEG content (wt.%) Fig 3 Variation of boiling temperature of lean amine solution

containing 45 wt% MEDA as a function of MEG loading

keep the iron in the aqueous solution, rather than

lead-ing it to create a protective layer on the metal;

The simulation results also indicated that for the same

circulation rate at the same process conditions, when

MEG content in amine loop were 0, 5, 15, 0 and 25 wt%,

the regenerator bottom temperatures were 129.6, 130.6,

131.8, 133.2, 135.2 and 137.7 °C, respectively The field

H 2 S absorption

kg MDEA) occurs at the minimum MEG concentration (0 wt%) Actually, the zero value of MEG concentration indicates the used lean amine has become discharged from the tank and the fresh amine is loaded into the tank In a case, from the field data, the reboiler tempera-ture was 128 °C with MEG concentrations of 10 wt% in gas treating trains #1 and #2 while in trains #3 and #4, the reboiler temperature was 133 °C with 20 wt% MEG concentration As mentioned, to prevent primary or sec-ondary amines formation in MDEA solution, the reboiler

the presence of MEG in the MDEA solution increases the reboiler temperature and decreases the acid gas loading

sweet-ening unit for five different cases contains 1, 5, 10, 15,

con-centration in sweet gas increased from 1.09 to 3.78 ppm

as MEG content increased from 1 to 25% in amine loop Therefore, the field and simulation results indicated that

con-centration in amine loop But still, MDEA in presence of

The simulation results showed that the energy con-sumption of regenerator reboiler increases from 39,165,295 (Case 1) to 41,274,795 kJ/h (Case 2) In other equipment, the energy consumption was not changed considerably Totally, the energy consumption in gas sweetening unit increased 5.4% in the case of 25  wt% MEG in lean amine solution while for 1 wt% MEG, the increase was 0.05%

CO 2 absorption

car-ried out via two different reaction mechanisms When

occurred to form carbonic acid, which in turn dissociates slowly to bicarbonate Finally, the bicarbonate undertakes

an acid–base reaction with the amine to yield the overall

Overhaul

125

128

131

134

137

Time (month) Fig 4 Regenerator bottom temperature in gas sweetening unit

Overhaul: scheduled shutdown maintenance

0 2 4 6 8 10 12 14

0

5

10

15

20

25

30

35

40

H 2

H 2

Time (month) Fig 5 MEG concentration versus acid gas loading in lean amine

solution

Table 4 H 2 S concentration in sweet gas obtained from the simulation for 1 to 25 wt% MEG content in the amine solution

CO (ppm) 14,369.89 14,406.39 14,452.50 14,499.18 14,548.98 14,600.70

MDEA reacts with CO2 via the slow CO2

bicarbonate So, increasing water concentration may

increasing MEG content in amine solution, water content

rich amine which must proceed in the regenerator So,

Corrosion

Work equipment in south pars refinery is commonly

inspected at suitable intervals (12 months) The

inspec-tion of the regenerator and reboiler during 36  months

showed severe corrosion in different parts of plants

including the vapor line of the reboiler, regenerator tower

between chimney tray and tray #7, vapor side of reboiler

around the vapor line nozzles, and behind the weir of

reboiler The changes in MEG concentration, HSS, and

Fe content in amine loop during 36 months are presented

between these parameters Corrosion may cause by HSS

through acid evaporation and condensing mechanism

in cold spots, as well as, the chelating effect of organic

(3)

(4)

(5)

+ R1R2R3N ↔ R1R2R3NH

(6)

acids and reduction of pH The high reboiler temperature (131–138  °C) can accelerate the condensation mecha-nism and acids evaporation Also, the chemical reaction rate (corrosion) becomes double for every 10 °C rise in reboiler temperature

Under thermal conditions, MEG degrades mainly

to glycolic acid with oxalic and partially to formic acid These degradation products promote corrosion by form-ing iron complexion In an amine system, similar to HSS,

rate in the gas sweetening unit for 20 and 25% wt% MEG

noted that the refinery’s goal is to keep the corrosion rate below 10 mpy The corrosion rate was less than 10 mpy

a typical example of corrosion observed in amine gas sweetening unit

BTEX and heavy hydrocarbon solubility

Benzene, toluene, ethylbenzene, and xylene (BTEX) are aromatic contaminants that can be permanently poi-soned the catalyst of Claus SRU BTEX can reduce SRU

The BTEX can be absorbed in the amine solution and removed from the flash drum and if not absorbed they are sent to the SRU According to the simulation results

solubil-ity of heavy hydrocarbon was increased about 60% As the amount of BTEX and heavy hydrocarbon were increased, the transferring of these components to the SRU unit was

hydrocar-bons in acid gas routed to the SRU It caused some side effects on SRU performance and leads to sooner catalyst deactivation A yearly evaluation catalyst was performed

in phases 2 and 3 The results showed that the efficiency

of catalyst decreased more than expected

Fig 6 H2S concentration in the inlet of the sulfur recovery unit

Fig 7 Total Fe content throughout the 36 months in amine gas

sweetening loop

Foaming in the amine absorber is a common problem In

an industrial plant, the differential pressure (DP) of the

absorber, the flow rate of flash gas (gas exited from the

flash drum), and the opening of LV0026 [level valve of the bottom of sweet gas Knock-Out (K.O)] are signs of foaming Parameters such as sour gas inlet temperature, bottom level of absorber, amine flow rate and tempera-ture, gas flow, antifoam concentration, homogeneity and flow rate, lifetime of filters, total suspended solids (TSS)

of amine, and lean amine quality have significant effects

on foaming formation

Amine absorber is equipped with DP cells to moni-tor system abnormalities As such observed in this

to 0.3 bar When foaming is formed in the absorber, the foam height increases with time, and subsequently, the void volume inside the column reduces, leading to higher pressure drop

After removing MEG from lean amine, the opening

of LV0026 shows amine carryover and DP of absorber

showed foaming are reduced in amine loop and the used amine has more TSS in compare to the fresh amine When there is severe foaming in the absorber, amine carryover from the absorber to sweet gas K.O drum While other effective parameters were in relatively con-stant conditions, flash gas and the opening of LV0026 were in a direct relationship with MEG concentration

foaming with 25 wt% MEG concentration in amine loop

MDEA contaminant analysis

The degradation products, HSS, metals and other con-taminants of amine in presence of 25% MEG were

Further-more, in this paper, for the first time, all necessary infor-mation for academic and industrial users, according to

allowable limit, source and effects of each contaminant in amine loop and the pros and cons of various operational conditions in amine gas sweetening processes This infor-mation leads users to investigate their own unit circum-stance However, to more evaluation, the composition

of used amine was analyzed The results obtained here showed that the composition of all components are in the allowable range but the composition of acetate in all gas treating units is more than allowable limit (1000  ppm), indicating MEG presence in amine loop

Operational remedies

There are numerous operational problems in the gas sweetening unit, especially excessive corrosion In order

to overcome these challenges, some techniques were car-ried out as follows:

Fig 8 Heat stable salts (HSS) value throughout the 36 months in

amine gas sweetening loop

Fig 9 MEG content throughout the 36 months in amine gas

sweetening loop

Fig 10 The corrosion rate of regenerator of MDEA unit trains #2 and

#4

Fig 11 Corrosion a in the vapor phase above the normal liquid level through the regenerator tower between chimney tray and tray #7; b in vapor side of reboiler around the vapor line nozzles; c through the reboiler shell of the regenerator behind the baffle

Table 5 Composition of acid gas routed to the SRU with lean amine solution containing 1, 5, 10, 15, 20, and 25 wt% MEG content

Composition (mole%)/MEG

Methylcyclopentane 0.000540 0.000574 0.000626 0.000692 0.000776 0.000885

• Dropping the bottom temperature of amine

regen-erator:

In this technique, the temperature and pressure at

the top of regenerator must be reduced The

tem-perature has a positive effect but the pressure has

not considerable effect Moreover, rich amine

existed from flash drum is entered to the amine/

amine exchanger and then routed to the

regen-erator If the efficiency of amine/amine exchanger

increases, the temperature of amine fed to the

regenerator will be increased and consequently

less steam is needed in the reboiler and the bottom

temperature of regenerator can be kept in lower

temperature But from the economical point of

view, this technique was not possible

• Applying a coating of Ceramium on the bottom of

the regenerator and around the nozzles of reboiler

• Applying proper insulation in the corroded area over

the vapor line to prevent condensation

• Changing the material of the vapor line of reboiler from carbon steel to stainless steel—grade 316 (SS316)

• Using partially refreshment of fresh MDEA (0.5 to 5.0%)

These techniques were effective but not enough Since there is not any facility for amine purification, it was decided to replace used MDEA with a fresh one and the

amine and consequently in sweet gas were high,

regeneration, the temperature of amine regenerator was increased from 98 to 110 °C and the bottom temperature

of regenerator was increased according to the tempera-ture at top of the regenerator It must be emphasized to this point that high bottom temperature can cause amine degradation To keep regenerator bottom temperature less than 132 °C, the amine flow rate was reduced from

residence time in the regeneration section and as a result,

of regenerator was decreased from 110 to 105 °C while the bottom temperature was kept less than 132 °C Since the fresh amine creates some problems in the amine gas sweetening unit, refreshment was partially carried out

in order to keep MEG content less than 10 wt% With results of this experience, it is suggested a few used-amine is added to the fresh used-amine after the construction

of the amine gas sweetening unit

These solutions were used to reduce the side–effects of MEG Therefore, it must be found an operational remedy

to avoid entering MEG to amine plant To achieve this purpose and regarding the design, the sweet gas is routed

to the gas dehydration unit and is then entered to the K.O drum (105-D-X01, where X = 1, 2, 3, and 4) of dew point-ing unit Bottom of this drum is returned to the amine flash drum Based on the simulation results, there is a considerable amount of MEG (between 0.5 and 4.0 wt%)

actual and simulated data of MEG% in this stream

Therefore, it was decided that this line be routed to the stabilization condensation unit in gas train #2 (second train) instead of routing to the amine flash drum The simulation of this plant also indicated that the equilib-rium amount of MEG in lean amine is 14 wt% When the bottom of the K.O drum is not routed to the flash drum and the concentration of MEG in amine loop is more than

14 wt%, the amount of MEG in amine loop decreases It was found that when the MEG concentration in amine

MEG>24%

MEG<15%

Overhaul

0.15

0.19

0.23

0.27

0.31

0.35

0 2 4 6 8 10 12

Time (month) Fig 12 Differential pressure of amine absorber, overhaul: scheduled

shutdown maintenance

MEG>24%

Overhaul

MEG<14%

0 10 20 30 40 50

0

200

400

600

800

1000

Time (month)

Flash gas

Fig 13 Flash gas from the flash drum and LV0036 opening overhaul:

scheduled shutdown maintenance